Centrifugal pumps are previously known for use down in oil-producing wells. These pumps employ a so-called multistage principle, where the pump consists of several vertically-arranged stages. A stage comprises substantially of an impeller and a diffuser. All the impellers are attached to a common shaft which passes through all the pump stages, and all of these stages are located inside one and the same casing. The shaft passing through all the pump stages is driven by an electric motor which is mounted on the underside (below in the longitudinal direction) of the actual casing. An example of this technology is the ESP or Electrical Submersible Pump which exists on the market today. The reason for using several pump stages is that each individual pump stage in itself has limited ability to deliver pressure increase. In order to achieve sufficient pressure, pumps of this type have to use several pump stages which are hydraulically connected in series and mounted on top of one another in the longitudinal direction.
However, there are disadvantages with the technical design of existing multistage pumps, such as, for example, that all the pump stages are driven by one motor via a common shaft, with the result that the whole pump stops if the motor stops. In addition, the existing constructions become very long due to the fact that the motor is mounted below the pump stages in the longitudinal direction. This is a problem when the pump is employed in wells where the well path is deviated relative to the vertical. In addition the bearings in today's pumps suffer from a short working life on account of severe loads and wear on impellers due to cavitation.
Production of hydrocarbons, and/or water for use in recovery of hydrocarbons and for other purposes, is carried out from reservoirs located down in rocks below the earth's surface. The vertical distance from the surface down to these reservoirs may vary from a few hundred meters down to several thousand meters.
The actual production is conducted either by means of artificial lift or by reservoir fluids, which may contain loose or free gas, flowing to the surface through a borehole/well because the pressure in the reservoir is higher than the pressure on the surface. Artificial lift is a common term for different methods and techniques which may be employed for this production. This present disclosure comprises equipment for improving artificial lift of hydrocarbons (with or without gas) and/or water to the surface. The choice of method for artificial lift is made on the basis of conditions in the reservoirs, the nature of the oil, the depth and well path of the borehole/well. In addition, importance is attached to the field's location (on shore or at sea) and the area's infrastructure, such as access to electric power and gas at the actual location. Based on these parameters, by means of the present disclosure the field operator can construct an installation which offers the best possible total economy based on the reservoir's production characteristics, investment in equipment and operating costs.
On shore fields with relatively shallow reservoirs and with reasonably vertical well paths, a system called a sucker rod pump is often chosen. In this case the actual drive gear is located on the surface, coupled to a pump unit down in the well via a pump rod. With this system the challenges are a relatively large drive gear which is located above and near the wellhead, friction between pump rod and pipe wall in the well, production of sand from the reservoir and a system efficiency of 0.4. There are also restrictions as to how deep this type of pump system can be located based on material/strength limitations on the pump rod. The systems have limited lifting capacity, and are therefore employed at lower production rates. The system's design per se, together with operating conditions such as sand production, leads to regular operational stoppages. In addition to increasing the direct operating costs, this leads to costs in connection with production delays. The length of stroke on the actual pump unit in a sucker rod pump is from two to three meters, and the frequency is from one to ten strokes per minute. In U.S. Pat. No. 5,179,306, a principle is described where the pump unit in a sucker rod pump is driven by a double-acting DC linear motor placed down in the well together with the pump unit in order thereby to avoid the challenges associated with the actual pump rod.
ESPCP and PCP are also systems which are used for artificial lift. In principle these are two identical pumps which differ in that ESPCP (Electrical Submersible Progressive Cavity Pump) is driven by an electric motor located down in the well, while PCP (Progressive Cavity Pump) is driven by a motor located on the surface. The power to a PCP is transferred from the surface to the pump down in the well via a pump rod, in the same way as for a sucker rod pump. The pumping principle employed in these pumps is often described as a screw pump where a rotor moves in a circular manner inside a specially-designed pump housing. ESPCP may be employed on installations both at sea and on shore, while PCP is only used on installations on shore. This type of pump is considered to be well-suited to production of heavy viscous oils, and generally considered to have an efficiency which is better than ESP which is described in the next paragraph.
An Electrical Submersible Pump (ESP) is a pump type which is widely used for artificial lift both at sea and on shore installations. The pump is mounted down towards the bottom of the well as an integrated part of the production tubing. This means that if the pump fails, the whole tubing has to be pulled out of the well. The actual pump consists substantially of an electric motor located in the bottom, from which there extends a shaft and on this shaft are mounted a plurality of impellers which are mounted in pairs with an associated diffuser, each such pair being called a pump stage. The number of pump stages mounted on the shaft from the electric motor is determined on the basis of the need for necessary lifting height (pressure), and large pumps may have more than 250-300 pump stages. The liquid is sucked into the bottom of the pump and with each pump stage the pressure is increased. In order to reduce the number of pump stages, the rotational speed can be increased, thereby providing a reduction in the total length of the pump. In U.S. Pat. No. 4,278,399, a solution is described for a more efficient pump stage in an ESP.
The efficiency factor of such ESP pumps is considered to be 0.3 and the volume flow can vary from a few hundred barrels per day to 20-30,000 barrels (1 barrel=158.97 liters) per day. The electric motor in the pump has power supplied from the surface through a special cable which is attached to the outside of the production tubing and the pump casing before being connected to the electric motor located in the bottom of the pump. The pump is controlled from the surface by means of a system called Variable Speed Drive (VSD). VSD transforms alternating current (AC) to direct current (DC) and back to an alternating current (AC) where the frequency can be manipulated. This manipulation of the frequency is used to alter the rotational speed of the pump. This creates wear on electric cables and connectors and may also lead to earthing problems.
Normally it is electric motors of the induction motor type which drive the actual pump, and on account of the need for a great deal of power in the case of high rates and deep wells, these motors become relatively long. In these motors there is little clearance between stator and rotor, with the result that small curvatures (deviations) in the well path can create contact between rotor and stator, leading to breakage. The same may occur due to vibrations in the motor in the case long motors of this kind of up to 20 m. On account of this situation, the industry has developed Permanent Magnet motors (PM motors) which have a more robust design. The mechanical challenges associated with ESP are wear and overheating of the electric motor, which PM motors are believed to be better able to tackle.
Substantial axial forces are also developed in the actual ESP pump. There are various solutions which are employed in order to improve this situation, one example of which is U.S. Pat. No. 5,201,848. This patent describes an impeller which does not assist in lifting fluid, but creates a static pressure which provides an upwardly directed force on the shaft. This is accomplished by the main impeller, which contributes to lift, being mounted on top of (in the longitudinal direction) a second impeller of the same volume, where the latter impeller has no circulation of well fluid.
Apart from the said mechanical problems, ESP systems have problems with handling the production of large amounts of sand and other solid particles such as scale. In addition cavitation occurs when free gas is produced from the reservoir. Both of these factors cause wear on the impellers. These factors can be counteracted by manipulating the rotational speed of the motor and thereby also the rotational speed of the impellers. Free gas is also a problem for the actual electric motor since the gas has less ability than liquids to transport the heat generated by the electric motor. All of these factors result in an estimated average life for an ESP system of around 1.5 years, but there are examples of these failing after only a few weeks in operation. The costs of replacing an ESP will vary with the depth of the well, due to the fact that the whole production tubing has to be pulled out. In addition to the direct costs of the operation, which involve the use of a drilling rig, the costs of production delays are also incurred.
One of the major weaknesses of today's ESP pumps is that all parts of the pump are integrated. As mentioned earlier, the shaft extends from the motor, continues through the entire length of the pump, and all the impellers are mechanically connected to this shaft. This means that if a breakage occurs on one or more of the components in the pump, the whole pump stops.
In Norwegian Patent Application No. 20100871 and in US Patent Publication No. US2002/0066568 A1 now U.S. Pat. No. 6,811,382, solutions are described where the pump is composed of steps consisting of motor, impeller and diffuser.
Gas lift is widely used as artificial lift on installations at sea where there is access to produced gas from the separator unit located on the installation. The principle is based on re-injecting produced gas into the annulus, or more specifically the production annulus, between the production tubing and the casing and down towards the production packer in the bottom of the well. Gas lift valves are placed at different levels in the tubing. These are one-way valves which permit the gas in the annulus to flow into the tubing, thereby reducing the pressure of the hydrostatic column inside the tubing. This occurs because the gas has a lower density than the fluids inside the tubing, thereby causing the hydrostatic counter-pressure on the reservoir to also be reduced, with the result that, by means of the injected gas, the reservoir pressure itself can force the produced fluids to the surface. In principle gas lift is an efficient system, but it requires investment in separate gas compressors, surface flow lines, Annulus Safety Valves (ASV), gas lift valves (GLV) and gas-tight pipe threads in the casing. The system can be difficult to operate in an optimal manner since the rate of mixture between oil, water and any gas produced from the reservoir will vary with shorter or longer intervals of time. In addition there is the problem that re-injected gas in the production annulus may leak out into the outer annuli through the casings. In order to reduce the risk of uncontrolled discharge of gas in the event of a system failure, several oil companies now want to develop an ISO V0 version of the gas lift valves so that they can remove ASV, since it has been shown that these ASV's are subject to leakages. This change will help to increase the investment costs for the gas lift system.
Single-acting and double-acting piston pumps are previously known for use in artificial lift. Apart from different designs of the actual pump housing (the pistons) and inlet and outlet valves, there are several different driving mechanisms for the pumps. Everything from electromagnetic motor solutions to solutions with linear motors is involved. In addition a single-acting piston pump is known which is driven by an induction motor which in turn drives a hydraulic unit which in the next phase drives the piston and valves in the pump. This kind of solution is often designed for operation of more than one single-acting piston in the pump. The common feature of all the pumps is that they are intended to be installed down in the bottom of the well. In U.S. Pat. No. 1,740,003 an electrically operated double-acting piston pump is disclosed. In order to reverse the piston movement, the phase of the motor is changed so that it rotates in the opposite direction. With a frequency of between 30 and 60 strokes per minute, there is substantial wear on the contacts which have to reverse the electrical current, and considerable heat generation every time the piston has to change direction. So far no one has managed to make linear motors which are practical and commercial, because, amongst other things, there is a huge increase in power consumption every time the motor has to change direction.